The present invention relates to an improved system and method for heat recovery for power recovery cycles; in particular for use in thermodynamic energy storage devices being retro-fitted to existing thermal processes in order to optimise the balance between cost and performance within the constraints of the existing thermal process.
Electricity transmission and distribution networks (or grids) must balance the generation of electricity with demand from consumers. At present, this is normally achieved by modulating a generation side (supply side) of the network by turning power stations on and off and/or running some power stations at reduced load. As most existing thermal and nuclear power stations are most efficient when run continuously at full load, balancing the supply side in this way results in an efficiency penalty. Significant intermittent renewable generation capacity, for example using wind turbines and solar collectors, is currently being introduced to the networks, and this further complicates the balancing of the grids by creating uncertainty in the availability of portions of generation capacity.
Energy storage devices and systems typically have three phases of operation: charge, store and discharge. Energy storage devices typically generate power (discharge) on a highly intermittent basis when there is a shortage of generating capacity on the transmission and distribution network. This can be signalled to the storage device operator by a high price for electricity in the local power market or by a request from the organisation responsible for the operating of the network for additional capacity. In some countries, such as the United Kingdom, the network operator enters into contracts for the supply of back-up reserves to the network with operators of power plants with rapid start capability. Such contracts can cover months or even years, but typically the time during which the power provider will be operating (generating power) is very short. A storage device can provide an additional service in providing additional loads at times of oversupply of power to the grid from intermittent renewable generators. Wind speeds are often high overnight when demand is low. The network operator must either arrange for additional demand on the network to utilise the excess supply, through low energy price signals or specific contracts with consumers, or constrain the supply of power from other stations or the wind farms. In some cases, especially in markets where wind generators are subsidised, the network operator will have to pay the wind farm operators to ‘turn off’ the wind farm. A storage device offers the network operator a useful additional load that can be used to balance the grid in times of excess supply.
For a storage system or device to be commercially viable the following factors are important: capital cost per MW (power capacity), capital cost per MWh (energy capacity), round trip cycle efficiency and lifetime with respect to the number of charge and discharge cycles that can be expected from the initial investment. For widespread utility scale applications, it is also important that the storage device be geographically unconstrained, i.e. that it can be built anywhere; in particular next to a point of high demand or next to a source of intermittency or a bottleneck in the transmission and distribution network.
One such storage device technology is the storage of energy using a cryogen (Liquid Air Energy Storage (LAES)), such as liquid air or liquid nitrogen, which offers a number of advantages in the market place. Broadly speaking a LAES system would typically, in the charge phase, utilise low cost or surplus electricity, at periods of low demand or excess supply from intermittent renewable generators, to liquefy a working fluid such as air or nitrogen during a first liquefaction phase. This is then stored as a cryogenic fluid in a storage tank during a storage phase, and subsequently released to drive a turbine, producing electricity during a discharge, or power recovery, phase at periods of high demand or insufficient supply from intermittent renewable generators.
The power recovery turbine of a LAES system operates by drawing liquid air or nitrogen (liquid air from here on) from a low-pressure, thermally insulated cryogenic storage tank, pumping it to high pressure, heating it to form a gas at high pressure, and expanding it in a turbine or other expansion device to recover work, which can be transformed into electrical power using an electrical generator. As with any thermodynamic power cycle, a determining factor of the power that may be recovered is the difference between the high-temperature and low-temperature ends of the cycle. The larger the temperature difference, the more power can be extracted. The saturation temperature of liquid air at ambient pressure is approximately minus 190 degrees Celsius. Therefore, even heating the air to ambient temperature affords a significant output of power.
The power output of a LAES system, and therefore the round trip cycle efficiency, can be improved by utilising waste heat from a collocated process, for example from a thermal power plant or industrial process such as a steel works, to heat the liquid air to a higher temperature than ambient temperature. The term “collocated process” thus refers to a system collocated with and external to the LAES system. This definition applies whenever the terms collocated process, collocated thermal process or external process appear in this specification. From the point of view of the collocated process, the thermal efficiency of the collocated process is also improved.
EP2663757 describes a LAES power recovery system wherein the working fluid may be heated using waste heat from a collocated process. The system comprises one or more expansion stages. Waste heat is transferred from a different heat transfer fluid to the gaseous working fluid to heat it prior to expansion in each of the one or more expansion stages. A skilled person will recognise that the different heat transfer fluid may indeed be the source of waste heat itself, for example in the case of the exhaust gases of an engine.
One application for a LAES system is in conjunction with a peaking plant. Peaking plants typically operate for very short periods of time, for example a few hours per day, in order to respond to peaks in demand on the electrical grid. In the peaking application, a LAES system will charge by liquefying air during times of low demand, for example at night. The LAES system operates in power recovery phase simultaneously with a thermal peaking plant and recovers heat directly from the operation of said thermal peaking plant, to improve performance.
In a typical design for a LAES system integrated into an Open-Cycle Gas Turbine (OCGT) peaking plant, heat is recovered directly from the exhaust stack of the turbine. The LAES power recovery cycle comprises multiple stages of expansion with a reheat heat exchanger between each stage. The reheat heat exchangers are situated directly in the turbine exhaust stack.
FIG. 1 shows a known power recovery system 10. Liquid air is drawn from a cryogenic tank 100, pumped to 140 bar in a cryogenic pump 200 and evaporated in an evaporator 300 to form a gaseous, high-pressure working fluid at approximately ambient temperature (e.g. 15° C.). The cold recovered from the evaporator 300 may either be ejected to atmosphere or recovered in a cold storage system to be used later in the charge phase of the LAES system.
The high-pressure working fluid is then conveyed to a waste heat exchanger 401 which is thermally coupled to an exhaust stack of an Open-Cycle Gas Turbine. At waste heat exchanger 401, the high-pressure working fluid is heated in heat exchange with the exhaust gases of the OCGT to approximately 450° C.
The heated high-pressure working fluid is then conveyed to an expansion stage 501 (e.g. comprising an expander) where it is expanded to produce work. The exhaust working fluid from the expansion stage 501 is then conveyed to another heat exchanger 402 that is thermally coupled to the exhaust stack of the OCGT where it is reheated ready to be expanded again in another expansion stage 502. This process is then repeated as desired.
When building a new LAES system and integrated collocated thermal process, the thermal process and LAES plant are ideally located in close proximity to allow for easy transfer of heat from the thermal process to the LAES system. However, LAES is particularly suited to retro-fitting of existing thermal processes to improve their thermal efficiency and revenue generation. On existing sites, there are often significant space constraints. The space available for the construction of a LAES plant may be a significant distance away from the point at which the waste heat is available from the collocated thermal process. In this specification, the term “thermal process” refers to a thermal system.
According to the configuration shown in FIG. 1, this means that a significant length of pipework is required to convey the working fluid to and from the source of waste heat (in this case, the exhaust stack of the OCGT) between each stage of expansion. Long lengths of pipework incur significant cost, in the pipework itself, and in the supports and thermal insulation thereof. Furthermore, the pipework introduces higher pressure drops, which impact on the performance of the cycle. This can be mitigated by increasing the diameter of the pipework, as is known in the art, but this further increases cost.
An alternative known design is to transfer heat indirectly from the source of waste heat (e.g. the OCGT) to the LAES power recovery cycle using an intermediate loop with a heat transfer fluid such as water, thermal oil or a gas such as air or nitrogen. This allows the designer to use a single return to the source of waste heat, with one pipe to and one pipe from the waste heat source. However, such systems add thermal inertia and slow down the startup of the LAES system, which can be critical in meeting the requirements for services to the electrical grid.
For high temperatures, such as those available in the exhaust stack of an OCGT, water heat transfer fluid would need to be held at high pressure to avoid boiling. For example, to transfer heat at 275° C., water would have to be held at upwards of 60 bar. This incurs the significant material, engineering and maintenance costs associated with high-pressure systems and maintaining the pressure within the system. It would also need to be managed to avoid freezing, at further financial and energy cost. Oil-based systems also present a fire and pollution risk.
A gas-based system would be more energy intensive, requiring more power to recirculate the gas.
There is therefore a need to minimise system costs while maintaining the performance of the power recovery cycle for LAES installations using direct heat transfer with a distant source of waste heat.